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Downhole fluid sampling

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Downhole sampling of fluids, also referred to as bottomhole sampling, is a key component of most hydrocarbon fluid sampling programs. The procedures outlined here apply to reservoir fluids or production streams above ambient pressure, and they are highly specific to the petroleum industry. The American Petroleum Institute publishes a detailed recommended practice,[1] which is the most complete industry standard covering the sampling of pressurized hydrocarbon fluids. It should be consulted for additional information to that presented here.

Production sampling

The production downhole sampling operation involves running a special sampling tool into the well on wireline so that a sample of the fluid in the well can be collected under the increased pressure of the fluid column. Careful well conditioning is necessary to ensure that the fluid is in a monophasic condition. Modern samplers are triggered either by a timer with a mechanical clock in the tool itself or by an electric signal conveyed by electric line. The former system is more common, being able to be run with any wireline unit, but it has the inconvenience of needing a preset delay to allow the tool and well to be set up for sampling. The sampler should be lowered into the well until it is a short distance above the upper limit of the perforated interval (unless there are mechanical limitations that prevent the tool from reaching this depth) to collect a sample that is representative of all the produced intervals. Various drillstem and tubing-conveyed installations are available for downhole samplers, which allow them to be operated without the use of wireline. These can allow samples to be collected downhole in high-risk wells in which wireline operations are not permitted.

One advantage of downhole sampling is that it can be performed without a separator at the well. There are several problems that can occur during downhole sampling. These are the following: (1) the fluid around the sampler may be in two-phase condition, or it may have segregated in the wellbore, (2) a mechanical problem with the tool can lead to incorrect opening or closing of the device (3) the fluid may be contaminated with water or drilling mud, or (4) the fluid sample may not be fully mixed before transfer into a shipping bottle. Use of a pressure survey may help check the location of any fluid interfaces in the wellbore, but a lack of an interface does not guarantee that the fluid present has not lost any material in the form of condensation, wax or asphaltene precipitation.

It is common practice with downhole samples to be transferred at the wellsite. This practice promotes obtaining a high quality sample and can allow for additional sampling runs to be made while still at the wellsite. If the samplers are supplied by a service company, this approach can reduce rental charges for the downhole samplers. It is considered best practice to transfer the entire downhole sample in one operation and to have the transferred sample well mixed (homogeneous). Samplers containing moving metal parts to facilitate mixing are now common and are preferred. General recommendations to be followed for downhole sampling are given in Table 1.

Sampling with formation testers

The collection of reservoir-fluid samples by formation-test tools was originally a secondary benefit to their use for measuring pore pressures. Formation-test tools can obtain reservoir-fluid samples without producing the well to the surface. The tool is typically run into an openhole well containing drilling mud or completion fluid. Once the tool has been run to the appropriate depth, a probe is forced against the formation. The probe is designed to provide a seal against the borehole wall such that only formation fluid can flow into the tool. Modern formation testers generally can be equipped with numerous devices designed to collect samples of reservoir fluid in a series of sample chambers. These tools offer the advantage of collecting reservoir fluid samples without performing a drillstem test (DST) and flowing fluid to the surface. They can be useful in obtaining fluids from a number of discrete depths, thus helping to identify possible fluid gradients. However, the disadvantage to using this technique is that there is limited well cleanup prior to sampling. This results in drilling mud filtrate contamination of the formation fluid sample. These problems have been reduced by methods that allow continuous pumping of sample fluid through the container into the wellbore while having the ability to monitor the quality of reservoir fluid flowing into the tool. Nevertheless, collected samples almost always contain some contamination from mud filtrate and sometimes from small quantities of water used to fill connecting lines during tool preparation. However, if the drilling mud is water-based, such contamination can be easily separated in the laboratory. Contamination is an HSE concern when sampled fluids contain H2S and CO2.

When sampling from wells that have been drilled with oil based mud (OBM), contamination is more difficult to detect and impossible to physically remove. Advanced spectroscopic detection systems have been developed for formation-test tools, but the industry is now beginning to accept that there always will be problems with formation-test sample contamination when OBMs are used. As a result, laboratories have developed various methods for evaluating the level of contamination and estimating the true physical properties of uncontaminated reservoir fluid.[2] In fact, this problem is not limited to formation-test samples because in some cases, production testing may not fully clean up OBM filtrate, especially if there have been significant losses during drilling.

Formation-test tools must be run by experienced engineers and wireline operators. Additionally, significant differences exist between different tools available on the market. Further, technological developments are occurring all the time, so specific operating details will not be given here. However, in addition to the well preparation as described earlier, a number of recommendations can be made to promote a quality sampling process:

  • Planning must optimize the match between tool capability and sampling and analysis needs.
  • Sample sizes collected should be compatible with storage containers so that individual samples can be transferred in their entirety.
  • Sample chambers containing mixing devices are to be preferred because they facilitate sample homogenization before transfer; where possible, duplicate samples should be taken from each depth sampled.
  • To determine depth gradients, samples should be collected from at least three different depths spanning the reservoir interval; when available, fluid-quality monitors should be used to evaluate cleanup of the fluid entering the tool.
  • The fluid-sampling rate should be adjusted where possible to minimize pressure drawdown. In the event, that downhole bubblepoint measurement or estimation is available, higher sampling rates can be performed within the tool specfications.
  • If OBM is used in the drilling process, prior to fluid sampling, contact a laboratory, capable of analyzing the contaminated samples, for advice on the amount of mud and fluid sample required for analysis. For some correction techniques, samples are required from the same depth with different levels of filtrate contamination.
  • Use of the formation-tester pump to compress collected samples (sometimes referred to as "overpressuring") may help reduce the effects of cooling, but it should not be used if final pressures are to be used as a measure of sample quality. If phase segregation from cooling is to be avoided, single-phase sample chambers should be selected as described below.
  • If fluid pumpout into the well is not possible (e.g., for safety reasons—H2S, low overbalance, etc.), large sample chambers should be used at the start of sampling to serve as "dump" chambers to allow for better-quality sample collection.
  • The depth and sampling time must be recorded together with the serial number of each chamber.
  • If possible, avoid using OBM when drilling, or switch to water-based mud for probable hydrocarbon-bearing intervals. Handling and transfer of formation-test samples should be along the lines described above for production-test downhole samples.

Single phase sampling

Downhole samples cool down as they are pulled out of the well. The associated pressure drop will usually result in the sample developing two phases inside the sample chamber, thus the need for homogenization before sample transfer. There are special versions of downhole samplers known single-phase or monophasic samplers that are available for this purpose. These samplers use the release of gas pressure behind a piston to maintain the downhole sample above reservoir pressure while pulling the tester to surface. This sampler design is used for reservoir fluids which are likely to precipitate asphaltenes during pressure reduction. These fluid types would be difficult to homogenize and without maintaining pressure on the smaple. For other fluids, single-phase samplers facilitate sample transfer and reduce the chance of the transferred fluid not being representative of the fluid in the sampler or in the reservoir. A disadvantage of the one-phase sampler is that a "bubblepoint check" cannot be performed on site because the gas buffer will mask sample behavior. One solution to this limitation is to run a conventional sampler in tandem to permit a quality check on one of the samples.

In most cases the single-phase sampler will prevent the formation of a gas phase, however it does not prevent the precipitation of waxes from waxy reservoir fluids, which can occur with cooling. A sampler with a heated chamber is available but has not been widely used. Also, gas/condensate fluids undergo significant shrinkage during cooling, and single-phase samplers may not prevent the formation of condensate in the sample chamber. Single-phase versions of formation-tester sample chambers are also available on the market.

Other downhole sampling tools

Other tools can be used to collect downhole fluid samples. DST Tools with chambers can be used, but there must be some upfront planning as problems can arise from recovering valid reservoir samples from the tool. Preference must be given to tool configurations that allow samples to be homogenized, transferred under pressure and contained in a single storage cylinder. Industry practice now favors the use of standard wireline samplers conveyed into the well as part of the DST tool.

Transferring downhole samples

Downhole fluid samples are commonly transferred to shipping bottles at the wellsite. The following subsection describes a method suitable for most downhole production samples and many formation-test samples. It may need to be modified according to the actual type of transfer equipment available.

API RP 44 method

If the sampler itself is not used to transport the sample to the laboratory, the sample must be transferred to a transfer container for shipping or transport. Whatever vessel is used, it must have an adequate pressure rating and be certified to meet all applicable shipping regulations. Further, the shipping cylinders must be cleaned thoroughly; this is particularly important to avoid contamination of the sample from trace amounts of heavy components remaining in the cylinder from previous use.

The primary concern in transferring a downhole sample to a shipping container is to maintain the integrity of the sample during the transfer operation. This requires that the fluid in the sampler be maintained in a single-phase condition during the entire sample-transfer process or, if the fluid is in a two-phase condition, that the entire contents of the sampler be transferred. (The sampler should be heated if wax or asphaltenes are present.) If only a portion of a two-phase sample is transferred, the fluid transferred to the shipping container will differ from the original sample because the two phases in the sampler almost certainly cannot be transferred in the proportions that exist in the sampler. Because valid transfer is crucial to sample quality, the preferred procedure is to maintain the fluid as a single-phase and transfer it in its entirety. An important consideration is that pressurizing the sample may produce a single-phase condition but may not homogenize the sample; thus, thorough agitation (by rocking the cylinder) during the process is important.

In addition, the sample composition must not be altered in cases in which the transfer fluid is in direct contact with the sample either by

  • Leaks of hydraulic fluid across the piston in piston-type samplers
  • Selective absorption of components from the sample into a transfer fluid (e.g., water or glycol)

The latter is a particular problem in samples containing CO2 or H2S, which are very soluble in the transfer fluid.

At all stages of the transfer process, the pressure must be maintained substantially higher than the sample saturation pressure. Fig. 1 shows a schematic diagram of a transfer apparatus for piston-type samplers and transport containers. The 1966 Edition 1 of API RP 44[3] should be consulted for transfer apparatus involving direct contact between the sample and mercury (as the hydraulic fluid).

The transfer procedure is as follows:

  1. Use the pump to fill all lines between valves B and F with hydraulic fluid (refer to Fig. 1). This can be done by loosening the fittings at these valves and pumping until hydraulic fluid appears, then tightening each fitting. Note: Valves A and B and F, G, and H may be integral parts of the sampler and transfer container, respectively, depending on the design of these vessels. Also, valve H and its line may be arranged somewhat differently from Fig. 1 so that valve H simply "tees" into the line from valve A to valve G. (this seems like it should all be italics, rather than stopping at Fig 1)
  2. With valves A, D, E, and F closed and valve C open, slightly open valve B and note the opening pressure of the sampler. Valve B is often hydraulically or spring-actuated in cases in which it is part of the sampler; if so, use the pump to raise the pressure until valve B just opens, and record the opening pressure.
  3. Open valve G and evacuate through valve H the line between valves G and A, including the sample side of the transfer container.
  4. Close valve H.
  5. Open valve F and use the pump to bring the hydraulic oil pressure in both the sampler and the shipping container to a pressure well above the saturation pressure of the sample.
  6. Slightly open valve A and fill the line between that valve and the upper face of the piston in the shipping container with sample fluid, using the pump to keep the pressure on the gauge well above the saturation pressure during this transfer process.
  7. Close valve C, then slightly open valve D, allowing hydraulic fluid to drain slowly into the hydraulic oil reservoir (open to atmospheric pressure) as fluid flows from the sampler to the shipping container. Use the calibrated pump to (a) keep the pressure in the sampler above the saturation pressure and to (b) keep track of the amount of sample transferred. When the desired amount of sample has been transferred, close valve D, then close valves A and G.
  8. Before the transferred sample can be shipped, a vapor space must be created in the shipping container. To do this, slightly open valve E and allow hydraulic oil to drain from the shipping container into an open calibrated receiver. Close valve E, then valve F, when the volume of hydraulic fluid in the receiver equals 10% of the volume of the shipping container. This will result in a 10% vapor space ("ullage" or "outage") in the shipping container. Such a void volume is required for safety because very high pressures can result if the temperature increases even slightly in a totally liquid-filled, closed vessel. Note: Special sample cylinders with an auxiliary gas cap are available for samples that must be retained in single-phase (monophasic) condition.
  9. Close valve B if it is not self-sealing. Open valve C, then valve D, to relieve pressure in the pump. At this point, the sampler and shipping (transfer) vessel can be disconnected from the transfer apparatus.


  1. API RP 44, Sampling Petroleum Reservoir Fluids, second edition. 2003. Washington, DC: API.
  2. Hy-Billiot, J., Bickert, J., Montel, F. et al. 2002. Getting the Best From Formation Tester Sampling. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 29 September-2 October. SPE-77771-MS.
  3. API RP 44, Sampling Petroleum Reservoir Fluids. 1966. Washington, DC: API.

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

External links

American Petroleum Institute

API publications store

See also

Fluid sampling

Separator fluid sampling

PEH:Fluid Sampling